Who are the deep thinkers on the cutting edge of the grid? Here at Greentech Media, we’d like to think they’re the members of our new Grid Edge Executive Council -- the group of energy and technology business and policy leaders we’ve asked to help guide our new research and editorial focus on the future of the electric grid.

Paul De Martini is one of those leaders, one who has built his grid knowledge from the ground up. A 30-plus-year utility industry veteran of investor-owned utilities, as well as competitive wholesale and retail energy services, De Martini has worked on all sides of the energy enterprise, from electric systems operations and project engineering, to marketing and business development.

De Martini’s recent work includes papers on leveraging flexible distributed energy resources and related business models (PDF), grid control technology architectures (PDF), and policies to enable distributed and renewable energy resource integration (PDF). This week, I got on the phone to ask him some questions about the opportunities and challenges facing the industry as it seeks to apply technological and business innovation on the edges of the grid. Here are his answers.

Can you describe the challenges facing utilities and the modern energy complex, out on the edges of the traditional electricity distribution network?

Classically, the system was managed from a centralized perspective, with controllable supply and load, in aggregate, that was highly deterministic. The edge of the grid, from a supply-demand balance perspective, was at a substation level, because that’s where the real-time measurements were done on short time cycles -- four seconds or less -- to support automatic generation control.

The “edge” has been expanding over time, [moving] closer to the customer. In some places it’s already there. In demonstration, and even in practice in a few places, that edge has moved, in terms of supply-demand balance, to the customers’ device that might be providing a wholesale market service, or being controlled to help with a grid operation. There’s a wide range of distributed energy resources being brought into the mix, whether it be a distributed generator, responsive demand, energy storage or power electronics.

Even with distribution operations, which has more to do with reliability and power quality than supply-demand balance, there’s a set of operational services that has increasingly been provided by customers. We’re seeing customer resources being enlisted to manage real-time grid operations and distribution asset utilization. In these instances may be a customer’s energy management system or reached a little farther, to the end device itself, perhaps a smart thermostat or appliance. From an operation control systems standpoint, it’s very interesting to see how the boundaries have extended, in directions that I don't think most people realize are in process and happening. The old paradigm of the meter as the boundary for billing and service is blurring, and yet in many cases, regulation does not yet fully recognize the change.

So, part of what we need to do is to align the related policies to get to where we’re at already and [where we'll be] heading this decade. We need a new paradigm to understand the roles, rules to integrate customers’ devices to allow them to scale. If we’re to have hundreds of thousands, even millions of customer devices engaged in providing dynamic and continuous operational services, we need to have policies that scale as much as we need control systems and technologies to scale.

What are some state-of-the-art, real-world deployments on these fronts, both on the technology side and on the policy side?

On the policy side, we haven’t seen the state of the art yet -- it’s more of a work in progress. You’ve got several places, like California and Maryland with its Utility 2.0 proposal, that are actively looking at these questions. But, there are a growing number of venues around the country asking how policy and regulatory models need to evolve to increase customer participation and services to the grid in a way that scales economically for all stakeholders.

One area that is often overlooked is that we’re in transition from market economics to real-time grid operations, both in transmission and distribution. That introduces a different dimension than just market efficiency related to supply costs and transmission congestion. The transition from market efficiency, to include optimization of real-time operations using distributed resources, requires resources to be very firm -- they need to be able to respond for the specific service they need to perform. This means we need to evolve from “best efforts” discrete type of traditional demand response programs to fast and continuous response resources. NERC [the North American Electrical Reliability Corp.], in its long-term resource adequacy report, speaks to the need to firm up distributed energy resources so they can provide services to bulk power system operations. The same question is going on in distribution.

Fortunately, there are a number of technology firms that have come on the scene in the last five years or so that are addressing this need to integrate these distributed resources into real-time operational control systems. There is a growing recognition that it is essential to marry economic optimization with grid control systems. Economics and power flows cannot be treated separately at the scale that distributed energy resources [DER] are envisioned in existing policy in many places in the U.S. and globally.

What gaps remain to be addressed? How are cutting-edge developments working on these challenges?

One main challenge is that for critical operating systems, like the power system, there is a natural tradeoff between economic efficiency and reliability. Those are two different axes, and there is a specific tradeoff between the two. We have to look more carefully at this tradeoff as we rely on increasingly greater amounts of distribution connected DER. I don’t know how many people know that distribution systems are loosely coupled to transmission systems from a control system standpoint since the power flowed one way to customers. In contrast, transmission systems and market operations are more closely coupled. But even here, there are a number of operational activities done in real-time grid operations that are not priced or executed through market constructs. As we increasingly couple wholesale markets, real-time transmission and distribution operations with dispatchable customer resources we need to look at the economic efficiency and reliability tradeoff in a different ways. Part of the challenge is that economic optimization is a fundamentally different mathematical problem type than is power flow optimization, and the shorter the time cycle that is required for solving the mathematics, the less that operators can use approximations and rules of thumb.

We need to bring this issue into the policy discussion or we may find that the existing policies won’t scale operationally. DOE and university research, like that at Caltech, is working on the engineering solutions, and utilities and tech firms are creating new technologies like GRIDiant's modeling tools, Space-Time Insight's situational intelligence, or AutoGrid’s solution that start to address trade-off optimizations from planning through real-time operations. California’s recently announced proceeding to consider the next generation of flexible DER could be a very good venue to discuss these issues.

What about bringing customers into this new paradigm?

Customers are the heart of this distributed shift. But the industry has struggled to [develop] an effective economic value proposition for customers, one that broadly incents them to participate at a level that matches policy goals. We should shift the discussion from ‘We will build it and they will come’ toward understanding customer motivation more deeply and the market/product designs that will be more likely effective. This requires the use of “design thinking” -- not central-planner thinking. There’s been some very good work from Lawrence Berkeley National Lab to identify the particular value streams that people should consider. Also, we need to look to simplify and reduce the cost of participation, in terms of the customer acquisition costs, the cost of equipment, and measurement and settlement. This is a place where we may have been too narrow in thinking about the roles of all stakeholders.

Also, there are related utility business model questions. In many ways, we’re still using 1990s [era of energy market deregulation] thinking about business opportunities. That is a focus on a linear value chain, the generator-to-consumer model. It gets us into narrow thinking, and the problem is it’s a zero-sum game -- there’s a winner and a loser in that proposition. If we look at the industries that have evolved over the past fifteen years, coming out of the internet, people don’t look at a linear value chain any longer. They look at a value network. The ability to develop an ecosystem to create network economics (that’s a buzzword, but still) in terms of a way to leverage values so that everyone benefits -- those models have been extremely effective. In the modern economy, it’s very hard not to have that kind of value network to be effective. But that hasn’t yet happened in the utility industry. This is an area where policy leaders and other stakeholders ought to step back and say, 'Are we digging ourselves deeper into an old paradigm that doesn't work in this modern economy? Do we need to get out of the hole, look around at other industries and see how we can create greater customer value, and how all stakeholders can participate?'